Device for installation and flow test of subsea completions

ABSTRACT

A running string for a subsea completion comprises an upper section ( 70 ) which may be a coiled tubing (CT) injector unit as shown, or a wireline lubricator (FIG.  8 ). A lower section ( 60 ) provides wireline/CT access to production/annulus bores of a tubing hanger (not shown) attached to tubing hanger running tool ( 62 ). A flow package ( 64 ) in the lower section ( 60 ), together with BOP pipe rams ( 86 ) and annular seal ( 88 ), directs production and annulus fluid flows/pressures to the BOP choke/kill lines ( 78/76 ). The upper and lower sections allow installation and pressure/circulation testing of, and wireline/CT access to, a subsea completion, without the use of a high pressure riser.

FIELD OF THE INVENTION

[0001] This invention relates to installation and testing of completioncomponents such as tubing and tubing hangers in a subsea well.

INVENTION BACKGROUND

[0002] Typically tubing hanger installation for either a conventional orhorizontal subsea Cbristmas tree system utilises a riser as a method oflowering the tubing hanger to the wellhead/Christmas tree and as a meansof transporting fluids to and from the wellbore. The riser also acts asa means of transporting wireline and coiled tubing from the surface tothe desired location. The typical arrangement of installation equipmentis as shown in FIGS. 1a-1 d, with FIG. 1a showing a “conventional”completion and FIG. 1b a horizontal completion. In FIG. 1a, a BOP 10 islanded on and sealed to a wellhead 12. A marine riser 14 extends fromthe BOP 10 to a drilling vessel (not shown). The completion landingstring comprising a tubing hanger (TH) 16 and associated tubing (notshown), tubing hanger running tool (THRT) 18 and tubing hangerorientation joint (THOJ) 20 is lowered into the marine riser 14 on adual bore high pressure riser 22. A controls umbilical 24 is secured tothe riser 22 and extends from the drilling vessel to the THOJ and THRT.A surface tree 26 is secured to the riser 22 for control of well fluids.The corresponding FIG. 1b arrangement for a horizontal tree 28 comprisesa BOP 32 secured to the tree 28, and a landing string comprising a THRT30 for TH 34, a subsea test tree (SSTT) 36, an emergency disconnectpackage (EDP) 38, a retainer valve 40, a monobore riser 42 and acontrols umbilical 44; all run through a marine riser 46. A surface tree48 is secured to the monobore riser 42. If required, fluid communicationwith the tubing annulus may be established via the BOP choke and killlines 45, 47, or via a separate external connection (not shown).

[0003] For wireline operations, a lubricator 50 is attached to eithersurface tree 26 or 48, as shown in FIG. 1c. Similarly, a tubing injector52, comprising a tractor unit 54 and stuffing box 56, may be attached tothe surface trees 26, 48 for coiled tubing (CT) operations.

[0004] The high pressure riser system represents a sigificant proportionof the installation equipment total cost and can, in the case of smallprojects, significantly affect the profitability of individual wells.Historically the riser systems, which are usually purpose designedpipe-pipe coupling equipment, are regarded as non-reusable and have longlead times to design and produce for each project. In the case ofdeepwater wells the time to run equipment can significantly affect theoverall installed cost of a well. Furthermore, although someinvestigations into riserless drilling of the well have been carriedout, completion equipment currently in use requires a high pressureriser for instaltion of the tubing hanger. This negates some of the costsavings available from riserless drilling. Therefore elimination of theriser system will significantly reduce project costs and lead times.

[0005] For deep water applications, a dynamically positionedinstallation vessel is typically used and emergencies concerning vesselstation keeping are more likely to arise. This is of partcular concernduring extended well flow testing. It is desirable to improve speed andreliability of emergency disconnection of the riser system from the BOP.

[0006] U.S. Pat. No. 5,941,310 (Cunningham) discloses a monoborecompletion/intervention riser system, providing a conduit forcommunicating fluids and wireline tools between a surface vessel and asubsea well. A ram spool is provided, engageable by BOP pipe rams, toestablish fluid communication between an annulus bore and a choke andkill conduit in the BOP.

[0007] U.S. Pat. No. 5,002,130 (Laky) and U.S. Pat. No. 4,825,953 (Wong)disclose open water, subsea CT injectors and wireline lubricators, butdo not suggest the use of such equipment in subsea completionoperations, which normally utilise a BOP and marine riser attached tothe wellhead.

SUMMARY OF THE INVENTION

[0008] The present invention provides a flow package for installationand testing of subsea completions having an elongate body connected toor comprising a tubing hanger running tool; the flow package body isengageable by pipe rams or annular seals of a BOP in use, a first end ofa fluid flow conduit extending through the tubing hanger running toolfor connection with a production or annulus bore in a tubing hanger; asecond end of the fluid flow conduit being connected to a port in theside or upper end of the flow package body, whereby a sealed flowconnection is formed between a choke and/or kill line of the BOP and theport; characterised in that the flow package comprises a wirelinelubricator or coiled tubing injector installable within a marine riserand mounted to the upper end of the flow package body, therebyeliminating the need for a high pressure riser for well fluid transport.The flow package thus may be used to establish a flow path between thetubing hanger production or annulus bore and the BOP choke or killlines. Two such fluid flow conduits may be provided, having theirrespective first ends connectable to production and annulus bores in aparallel bore tubing hanger, and their associated ports connectable torespective ones of the BOP choke and kill lines by engagement of the BOPpipe rams/seals with the flow package body. When provided with a singleflow conduit, the flow package may be used to connect the verticalproduction bore of a horizontal tubing hanger to a choke or kill line ofthe BOP, preferably the choke line.

[0009] The prior art arrangement requires the completions riser to bedisconnected, followed by disconnection of the marine riser. Theinvention allows the installation string to be removed and the BOP ramsto be closed above the flow package prior to commencement of well flowtesting. This facilitates a simpler, more reliable and rapiddisconnection at the marine riser in an emergency, e.g. when theinstallation vessel is driven off station.

[0010] Advantageously, the or each flow conduit has an upper endproviding wireline or CT access to its associated tubing hanger bore.The flow conduit(s) may contain valves providing flow control andwireline/CT shearing capabilities.

[0011] The wireline lubricator or coiled tubing injector may be mountedto the upper end of the flow package body by a remotely actuableconnector, allowing substitution between the lubricator and CT injector.Where two flow conduits are provided in the flow package body, theconnector may provide for mounting of the lubricator/CT injector in twodifferent orientations, for connection with alternative ones of the flowconduits. Alternatively, a bore selector may be connected between theflow package body and the lubricator or CT injector. The coiled tubinginjector and/or wireline lubricator may be connected directly to theflow package body or bore selector.

[0012] A service line umbilical to the flow package may be run andretrieved together with the flow package, wireline lubricator or CTinjector, inside a marine riser connected to the BOP. Alternatively, theservice line umbilical may be located outside the marine riser, beingconnectable and disconnectable from the flow package by a remotelyactuable penetrator mounted on the BOP.

[0013] Additionally, or as a further alternative, an electrical/opticalcontrols line may be incorporated in the umbilical, whether inside oroutside the marine riser. This controls line may be used in conjunctionwith a source of pressurised fluid supplied to the flow package, to forman electro-hydraulic, or opto-hydraulic, multiplexed control system.

[0014] The necessary hydraulic fluid power may be supplied to the flowpackage via an open port in its upper part; in use BOP closure elementsbeing closed and sealed around the flow package body to define apressurisable space in communication with the open port.

[0015] The controls system thus reduces or even entirely eliminates thenumber of fluid lines in the service line umbilical. It may be used tocontrol the following hydraulically actuated functions of the flowpackage:

[0016] Latching/unlatching of the THRT to the TH (including hydraulicpull/push for powered connection/disconnection);

[0017] Actuation of the flow control valves in the flow package;

[0018] TH seal energization and lockdown, or TH retrieval;

[0019] Actuation of other equipment attached to the tubing hanger andtubing string, e.g. annulus valves, downhole safety valves, downholecontrol valves or chemical injection valves.

[0020] The controls system may also be used to provide feedbackconcerning the operating state e.g. of any of the controlled components.For example, appropriate position sensors can be connected to thevarious valves and actuators concerned, providing electrical or opticalsignals which are fed (if necessary with suitable multiplexing) back upthe controls line.

[0021] In a yet further embodiment, the control and feedback signals maybe sent acoustically, e.g. through the wireline, CT or drill pipe uponwhich the flow package is suspended. For this purpose, either or boththe surface equipment and the flow package may include appropriateacoustic signal generating and receiving equipment. The flow packagewill use the received electrical, optical or acoustic signals to controlsolenoid valves, selectively controlling the supply of pressurised fluidto the flow control valve actuators. It will also generate acousticfeedback signals indicative of actuator positions or other operativeconditions of interest. The flow package may incorporate an internalelectric power supply, so that when acoustic signal transmission isused, no electrical connection to the surface is required.Alternatively, a single electrical connection to the surface may beprovided for powering the solenoids and acoustic signalreceiving/generating equipment.

[0022] The invention thus provides apparatus that eliminates the risersystem during installation of a tubing hanger for any subsea completiondesign (e.g. dual bore conventional). This has the following benefits:

[0023] 1. For a horizontal subsea Christmas tree system no riser isrequired.

[0024] 2. For a conventional subsea Christmas tree system a riser wouldonly be required for installation/workover if coiled tubing through theChristmas tree were needed.

[0025] 3. Elimination of the riser reduces project costs and potentiallyinstallation times and costs.

[0026] 4. Coiled tubing operation could be performed during tubinghanger installation and thereby eliminate the use of an open water riserfor coiled tubing operations during Christmas tree installation.

[0027] 5. In the event of a vessel drive off or drift off scenario, themarine riser may be disconnected more rapidly due to the absence of theinternal completions riser.

[0028] The invention including further preferred features and advantagesis described below with reference to illustrative embodiments shown inthe drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

[0029] FIGS. 1a-1d show prior art completion installation equipment asdiscussed as background above;

[0030]FIG. 2 shows the basic configuration of a flow package, THRT andwireline lubricator/CT injector embodying the invention;

[0031]FIG. 3 shows a TH, THRT, flow package and wireline lubricatorembodying the invention landed in a BOP;

[0032]FIG. 4a is a diagram showing fluid flow paths, control valves andwireline access paths for a flow package embodying the invention, usedwith a wireline lubricator in a parallel bore conventional completion;

[0033]FIG. 4b illustrates a modification of the apparatus of FIG. 4a;

[0034]FIG. 5 corresponds to FIG. 4a but relates to a horizontalcompletion;

[0035]FIG. 6 is a comparative illustration of a prior art surfacewireline lubricator and a flow package and lubricator embodying theinvention;

[0036]FIG. 7 is a comparative illustration of a prior art CT injectorand a flow package and CT injector unit embodying the invention;

[0037]FIG. 8 illustrates the relationship, in use, between a flowcontrol package/wireline lubricator embodying the invention and thesealing components of a typical BOP;

[0038]FIG. 9a corresponds to FIG. 8, but is for a flow controlpackage/CT injector embodying the invention;

[0039]FIG. 9b shows a modification of the apparatus of FIG. 9a;

[0040]FIGS. 10a to 10 c show arrangements for running and retrievingcomponents of a flow control package/wireline lubricator embodying theinvention;

[0041]FIG. 11 is a diagram illustrating a BOP emergency shear disconnect(ESD) operation;

[0042]FIG. 12 shows an alternative embodiment of the invention for CTinjection;

[0043]FIG. 13 shows a possible modification to the previous embodiments;and

[0044]FIG. 14 is a diagram of a yet further modification, showing theflow package and attached tubing hanger.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0045] The overall landing string assembly shown in FIG. 2 has two majorsections: a lower section 60 comprising a THRT 62 attached to the flowpackage 64; and interchangeable upper sections 66 comprising a wirelinelubricator 68 and coiled tubing injector 70 as required. The flowcontrol package 66 acts as a wireline or coiled tubing BOP, similar to asurface equivalent. A remotely operable latch unit 72 permits the uppersection of the landing string to be unlocked and retrieved to thesurface for change out of wireline tools and coiled tubing 71. The THRT62 is engageable with a tubing hanger 74 for TH installation, completiontesting and wireline/CT operations.

[0046] As shown in FIG. 3, the BOP choke lines 78 may serve as a flowpath to the production bore 80 and the BOP kill lines 76 as a flow pathto the annulus bore 82 of a dual, parallel bore completion. Valves inthe flow control package 64 preferably control the flow, with the BOP 90using its pipe rams 86 and annular seal bags 88 to seal against thelanding string and thus provide pressure continuity. The tubing hanger74 is attached to the landing string, which is lowered to the wellheadon a wireline 75, chain, drill pipe, coiled tubing 71 or the like. Thelanding string assembly may include an orientation helix 92 whichinteracts with a per se known orientation pin or key projecting from theinterior wall of the BOP 90. Once the tubing hanger 74 is landed andlocked, the BOP 90 closes its appropriate rams 86 and annulus seals 88to provide continuity of the annulus and production bores. The annulusconduit 94 in the flow package 64 terminates at a port 96 in the side ofthe flow package 64 body. This port 96 comnunicates with the annularvoid defined between the flow package 64, TBRT 62, TH 74, pipe rams 86and surrounding BOP 90. The kill line 76 also communicates with thatannular void to complete the annulus flow path. Similarly, a productionconduit 98 in the flow package 64 terminates at a port 100, whichcommunicates with the annular void defined between the landing string,pipe rams 86, BOP annular seal 88 and BOP 90. The choke line 78communicates with the latter void to complete the production flow path.

[0047] Final completion of the well (e.g. installation of the Christmastree) may be performed using known methods, such as subsea wirelinelubricators etc.

[0048] The flow control package provides pressure containment andcutting facilities for example as shown in FIGS. 4a, 4 b and 5. For thedual parallel bore completion shown in FIG. 4a, flow control valves 102,104 are provided in the production conduit 98 below the port 100. Atleast one of these valves (e.g. valve 102) may provide cuttingcapability. A generally vertical continuation 106 of the productionconduit 98 extends to the top of the flow control package 64 to providewireline/CT access to the production bore 80. Conduit continuation 106contains a valve 108. Similarly, annulus conduit 94 has a valve 110, andan access continuation 112 above the port 96, containing a cutting valve114. Valve 110 may either be positioned as shown in FIG. 5, outside theTHRT section 62 of the flow package 64, or inside the THRT section asindicated in FIG. 8. Other valve arrangements will be readily apparent.For example, in particular circumstances certain valves may be redundantand can be omitted. Indeed, it may be possible to eliminate all of theflow control package valves and rely entirely upon the valves in theBOP. Additionally or alternatively, the valves may be replaced by otherclosure elements such as wireline installed plugs.

[0049] A bore selector 116 may be mounted on top of the flow package toprovide selective access from the single bore 118 in the wirelinelubricator 68 (or CT injector, not shown) to conduit continuation 106 oralternatively conduit continuation 112. The same function may beachieved by arranging the latch unit 72 to connect directly to the flowpackage 64 in two possible orientations. In one of these, as shown inFIG. 4b, the lubricator (or CT injector) bore 118 connects with theannulus conduit continuation 112 and the production conduit continuationis blanked off. In the other latch unit orientation (not shown), bore118 is connected to continuation 106 and continuation 112 is blankedoff.

[0050]FIG. 5 shows the equivalent flow control/access arrangements for ahorizontal completion. The annulus bypass loop 120 present in thehorizontal tree to provide fluid communication with the tubing annulus,bypassing tubing hanger 122, is connected to the BOP kill lines 76 inper se known manner by closing the BOP pipe rams 86. The port 100, andhence production tubing 124, is sealed in fluid communication with theBOP choke lines 78 by closing the BOP pipe rams 86 and annular seal 88.

[0051]FIG. 6 compares a prior art surface wireline lubricator shown onthe left, with a wireline lubricator 68 and flow package 64 embodyingthe invention, shown on the right. Each comprises a wireline pulley orsheave 126 supported on the drilling vessel. Instead of being directlyattached to the pulley 126 as in the prior art, the remainder of thelubricator and flow package of the inventive embodiment is run into themarine riser 128 to land the flow package 64 within the BOP (not shown),eliminating the high pressure riser. Both lubricators comprise arespective stuffing box 130 a, 130 b, and respective upper quick unions132 a, 132 b for tool changeout. (A tool 134 is shown in phantom on theright hand side of the figure, contained wholly within the assembly, toprotect it during trip in/trip out operations). The hydraulic latch 72of the inventive embodiment corresponds to the lower quick union 136 ofthe prior art lubricator. The prior art wireline valve 138, togetherwith the surface tree (not shown) to which the known lubricator isattached, corresponds to the flow package 64, with wireline valve 138corresponding to valve 108. Hydraulic and/or electrical service lines tothe latch 72 and flow package valves are provided via an umbilical 148.

[0052] Similarly, FIG. 7 compares a prior art tubing injector unit(left) with an injector unit and flow package embodying the invention(right). Each comprises respective tubing guide and straightener rollers140 a, 140 b supported on the drilling vessel. Again the remainder ofthe inventive injector unit 70 and flow package 64 is lowered into themarine riser 128, instead of being supported on the drilling vessel. Therespective injector units comprise stuffing boxes 142 a, 142 b andtractor units 144 a, 144 b. To fit within the marine riser 128, thetubing engaging caterpillar tracks 146 and the associated drive motorsof the tractor unit 144 b must be made somewhat smaller than isconventional. However, any resulting power loss is at least partiallyoffset by the fact that the inventive tractor unit 144 b is situatedvery close to the wellhead in use, and does not have to push the CTthrough a high pressure riser. Prior art surface tree 146 corresponds tothe flow package 64. Hydraulic and/or electrical service lines to thetractor unit 144 b, latch 72 and flow package valves are provided via anumbilical 150. The equipment can be controlled using a directhydraulic/electrical system or an electro-hydraulic multiplexed controlsystem.

[0053]FIG. 8 shows the lubricator 68, bore selector 116, flow package 64and THRT 62 stackup relative to the components of a typical BOP. In thisfigure, the BOP pipe rams are referenced P, BOP shear rams S and BOPannular seal bags A. Datum line 0 represents the level of the top of thewellhead; 0-I is the BOP lower double ram housing; I-II the BOP upperdouble ram housing, II-III the BOP lower annular seal housing; III-IV aspacer section; IV-V a BOP connector; V-VI the BOP upper annular sealhousing and VI-VII the marine riser flex joint. Line VII represents theinterface between the flex joint and the marine riser proper.

[0054]FIG. 9a shows an equivalent stackup for a CT injector 70, flowpackage 64 and THRT 62. FIG. 9b is a modification of FIG. 9a, in which arelatively short lower neck 152 on the injector unit 70 is replaced by alonger flexible neck 154 extending through the BOP/riser flex joint atVI-VII, so that the main body 156 of the injector 70 lies in the marineriser proper.

[0055] The landing string assembly can be run on a wireline oralternatively on coiled tubing or drill pipe (depending upon loading).The upper section (wireline lubricator or tubing injector unit) may nothave to be run during the initial installation. It need only be run whenready to perform the first wireline trip/coiled tubing operation. FIG.10a shows a wireline lubricator 68/flow package 64 assembly run andretrieved together on a wireline 75. FIG. 10b shows the lubricator 68retrieved on the wireline 75, separately from the flow package 64. Thisflow package may either be installed coupled to the lubricator 68 orinstalled separately by wireline (not shown) or by being lowered on theumbilical 148. FIG. 10c shows a modification in which the umbilical 148is run and retrieved together with the lubricator section 68. (Umbilical150 can likewise be modified for installation/retrieval with theinjector unit 70.) One possible alternative to lowering thetubing/landing string or separate upper and lower sections is to use a‘piston effect’, allowing the assembly or section to free-fall at a slowspeed in the marine riser 128, as the fluid in the riser is throttledbetween the assembly/section outside diameter and the riser bore. Forthis purpose, the component or assembly may be provided with a collar,fairly closely fitting within the marine riser bore and including athrough passage with a descent control throttle valve.

[0056] Referring again to FIGS. 4a and 5, the following table showsvarious flow or access paths established and pressure/flow/circulationtests performed on a dual parallel bore completion and a horizontalcompletion respectively, using a flow package embodying the invention.“O” denotes the relevant barrier component in the open or unsealedcondition and “” the closed or sealed condition. Valves Pipe Annular160 162 ram seal TH plugs Completion Test/Operation 102 104 108 110 114161 163 86 88 158 159 Dual Parallel Flow/pressure produc- ◯ ◯     ◯  ◯/ ◯ Bore (FIG. 4a) tion bore (well test) Flow/pressure in    ◯ ◯   ◯/ ◯ ◯/ annulus Downhole circulation ◯ ◯  ◯  ◯ ◯   ◯ ◯Circulation choke/kill ◯/     ◯ ◯ ◯  ◯/ ◯/ Wireline and CTaccess ◯ ◯ ◯       ◯/ ◯ to production bore* Wireline access to◯/ ◯/ ◯/ ◯ ◯ ◯/ ◯/ ◯ ◯ ◯ ◯/ annulus bore Testing TH plugs from ◯ ◯ ◯  ◯ ◯     above Alternative TH plug test^(†)  ◯/ ◯/  ◯/ ◯/◯/ ◯/ ◯/   Horizontal Flow/pressure in produc- ◯ ◯   ◯   (FIG.5) tion bore (well test) Flow/pressure in    ◯   ◯/ Annulus**Downhole circulation** ◯ ◯  ◯ ◯   Circulation choke/kill ◯/   ◯ ◯◯  Wireline and CT access ◯ ◯ ◯     to production bore

[0057] The flow package 64 preferably incorporates an emergencydisconnect package (EDP) 164 at its upper end (FIGS. 8, 9a, 11). In anemergency requiring rapid disconnection of the marine riser from thewellhead, the flow package valves 102, 104, 108, 110, 114, choke/killline valves 160, 161, 162, 163 and BOP pipe rams 86 are closed, withe.g. valves 102, 114 used to shear any wirelines, CT or the like passinginto the completion. Latch means are then released to disconnect the EDP164 from the remainder of the flow package 64. The EDP and attachedumbilical 148 or 150, and any attached upper section (wirelinelubricator or CT injector such as 68, 70, FIG. 2) may then be pulled,the BOP shear rams 166 closed and the BOP connector at IV-V in FIGS. 8,9a or 9 b released. The EDP latch means may be mechanically actuated forrelease by the BOP shear rams 166, and/or may be hydraulically actuated.Where the umbilical 148, 150 is retrievable with the upper section latchconnector 72 as shown in FIG. 10c, or where the umbilical is connectedto the lower section 60 by a horizontal penetrator assembly (describedin more detail below with reference to FIG. 13), it may be possible todisconnect at the latch 72 to leave the entire lower section behind atthe wellhead, particularly when wireline/CT cutting is not required. Inthat case the BOP pipe rams and/or annular seal 88 are used to seal theBOP lower section to the landing string lower section 60 and the BOPshear rams are left open.

[0058] This variation also allows for the EDP 164 to be deliberatelydisconnected before commencement of the flow test. The shear rams may beclosed above the disconnection point as shown in FIG. 11 to provide abarrier between the well test fluids and the bore of the riser. Controlof the valves in the flow package 64 is via the horizontal penetratorassembly. It may be preferable to provide an additional barrier to theproduced fluids in this scenario. This may be achieved by engaging anadditional set of pipe rams above the outlet port 100 onto the outsidediameter of the flow package. Alternatively, the role of the productionand annulus conduits may be reversed, with the production flow beingrouted via port 96 and the annulus fluids being routed via port 100,thereby providing additional barriers to the produced fluids. Thisalternative is also applicable to the embodiments of the inventionmentioned earlier.

[0059]FIG. 12 shows a modified form of CT injector embodying theinvention. The CT injector unit 70 is supported on the drilling vesseland is connected to the landing string lower section 60, comprising theTHRT 62 and flow package 64, by drill pipe 168 run into the marine riser128. Standard drill pipe is readily available having an internaldiameter sufficient for passage of CT up to five inches (127 mm) indiameter. A wireline lubricator may likewise be surface mounted andconnected by drill pipe to a flow package 64 landed in the BOP, providedthat the wireline tools concerned are of sufficiently small diameter topass through the drill pipe. In these embodiments the drill pipe servesas a cheaper and more readily available alternative to a custom designedhigh pressure riser system.

[0060]FIG. 13 concerns a modification of the previously describedembodiments. As shown in FIG. 13, the umbilical 148 or 150 is attachedto the outside of the marine riser, and is connected to the runningstring lower section 60, for example by a remotely actuated horizontalpenetrator assembly 170 mounted on the BOP, when the lower section 60 islanded in the BOP. With this arrangement, there is no need to run/pullthe umbilical with every tool or CT trip, thereby reducing the risk ofwear and damage to the umbilical. Also, the EDP can be disconnected andthe BOP shear rams closed prior to flow testing, with the flow packagevalves remaining fully remotely operable, as described above.

[0061]FIG. 14 shows a further modification, in which the flow package 60is suspended on a wireline, CT or drill pipe 75. A tubing hanger 74 andassociated tubing 200 are releasably attached to the lower end of theflow package 60. As shown, the flow package is conceptually divided intoa signal processing and control module 202, an actuator module 204 and aTHRT 62, although it will be readily apparent that the functionalcomponents of the module 202 may be located anywhere within the flowpackage 60 and the actuators may be located anywhere within the flowpackage 60, TH 74, or tubing string 200.

[0062] An aperture or open port 206 is used to admit pressurised fluidinto the upper end of the control module for powering the variousactuators in the actuator module 204, the TH 74 or downhole devices. Forexample the annular bags 88 (or, if available, the upper pipe rams) ofthe BOP can be closed and sealed about the flow package body below theport 206. Fluid in the space above the annular bags may then bepressurised for use as the hydraulic power source.

[0063] Solenoid valves in the control module 202 are used formultiplexing the hydraulic power to the various actuators as required.The solenoids are connected to suitable control circuitry, supplied withcontrol signals over an electrical or optical service line 208,extending to the surface. Service line 208 may also be used to provideelectrical power to the solenoids and control circuitry. Feedbacksignals e.g. from valves and actuators may be transmitted back up theservice line 208 to provide information at the surface concerning theiroperative state. Where the control and any feedback signals are insteadtransmitted acoustically through the wireline 75, and the control moduleis provided with an internal electric power supply, the service line 208is unnecessary.

1. A flow package for instalation and testing of subsea completionshaving an elongate body (60) connected to or comprising a tubing hangerrunning tool (62); the flow package body (60) being engageable by piperams or annular seals (86, 88) of a BOP (90) in use; a first end (80,82) of a fluid flow conduit (94, 98) extending through the tubing hangerrunning tool for connection with a production or annulus bore in atubing hanger; a second end of the fluid flow conduit being connected toa port (96, 100) in the side or upper end of the flow package body,whereby a sealed flow connection is formed between a choke and/or killline (76, 78) of the BOP and the port; characterised in that the flowpackage comprises a wireline lubricator (68) or coiled tubing injector(70) installable within a marine riser (128) and mounted to the upperend of the flow package body (60), thereby eliminating the need for ahigh pressure riser.
 2. A flow package as defined in claim 1characterised in that two said fluid flow conduits (94, 98) areprovided, having their respective first ends (82, 80) connectable toproduction and annulus bores in a parallel bore tubing hanger, and theirassociated ports (96, 100) connectable to respective ones of the BOPchoke ad kill lines (76, 78) by engagement of the BOP pipe rams/seals(86, 88) with the flow package body (50).
 3. A flow package as definedin claim 1 or 2, characterised in that the or each flow conduit (94, 98)has an upper end (106, 112) providing wireline or CT access to itsassociated tubing hanger bore.
 4. A flow package as defined in anypreceding claim, characterised in that the flow conduit(s) (94, 98)contain(s) valves (102, 104, 108, 114, 110) providing flow control andwireline/CT shearing capabilities.
 5. A flow package as defined in anypreceding claim characterised in that the flow conduit(s) (94, 98)contain(s) provision for wireline installed plugs (158, 159).
 6. A flowpackage as defined in any preceding claim, characterised in that thelubricator (68) or coiled tubing injector (70) may be so mounted in thealternative.
 7. A flow package as defined in any of claims 1 to 6,characterised in that the lubricator (68) or coiled tubing injector(70), where present, are so mounted by a remotely actuable connector(72).
 8. A flow package as defined in claim 7, characterised in that twosaid flow conduits (106, 112) are provided in the flow package body (60)and wherein the connector (72) provides for mounting of thelubricator/coiled tubing injector (68, 70) in two differentorientations, for connection with alternative ones of the flow conduits.9. A flow package as defined in claim 7, characterised in that two saidflow conduits (106, 112) with respective said second ends connected torespective said ports are provided in the flow package body (60) andwherein a bore selector (116) is connected between the flow package body(60) and the lubricator (68) or coiled tubing injector (70), wherepresent.
 10. A flow package as defined in any preceding claim,characterised in that the coiled tubing injector (70) and/or wirelinelubricator (68), where present, are located at or near the sea surface,connected to the flow package body (60), or bore selector (116) wherepresent, by drill pipe (168).
 11. A flow package as defined in anypreceding claim, characterised in that a service line umbilical (148,150) to the flow package (60) is located in use outside a marine riser(128) connected to the BOP and is connectable and disconnectable fromthe flow package (60) by a remotely actuable penetrator (170) mounted onthe BOP.
 12. A flow package as defined in any preceding claim,characterised in that hydraulic fluid power is supplied to the flowpackage, for operating associated actuators, via an open port (206) inan upper part (202) of the flow package, whereby in use BOP closureelements can be closed and sealed around the flow package body to definea pressurisable space in communication with the open port (206).
 13. Aflow package as defined in claim 12, characterised in that the suppliedhydraulic power is multiplexed to a plurality of actuators by solenoidvalves and associated control circuitry.
 14. A flow package as definedin claim 13, characterised in that control signals are supplied to thecontrol circuitry over a service line (208) extending to the surface.15. A flow package as defined in claim 13, characterised in that controlsignals are provided to the control circuitry acoustically.
 16. A flowpackage as defined in claim 15, characterised in that the acousticcontrol signals are transmitted from the surface to the control packageover a wireline, CT or drill pipe string (75) from which the flowpackage (60) is suspended.
 17. A flow package as defined in anypreceding claim, characterised in that feedback signals are sent fromthe flow package to the surface in use, to provide information as to theoperative state of valves and actuators.